This invention relates to ball sealers that are used during fluid injection operations in oil wells.
Oil and gas wells are typically constructed with a vertical underground pipe, or casing, surrounded by a concrete sheath. This structure permits the flow of fluid between the casing and the surrounding formations to be limited to selected zones. The well operator determines which strata he wishes to collect hydrocarbons from or inject fluid in, and then perforates the casing and concrete at that level (or levels).
One operation which is frequently performed on oil wells is the injection of fluids into the surrounding formations. One specific example of a fluid injection operation is hydraulic fracturing. In this operation, a fluid such as water which contains particulate material such as sand is pumped down from the surface into the casing and out through the perforations into the surrounding formations. The particulates lodge in tiny cracks in the target formations and serve to "prop" those cracks open. This increases the permeability of the formation and therefore increases the flow of hydrocarbons into the well when fluid injection ceases.
In order to maximize the beneficial effect of an operation like hydraulic fracturing, it is important that the fluid be injected into the surrounding formations with a fairly even flow distribution in all directions. However, achieving an even distribution can be difficult, because the formations surrounding the perforated zone may not be of equal permeability. The fluid will preferentially flow to the areas of least resistance, i.e. the areas of highest permeability, and low permeability areas will receive correspondingly reduced flow rates. This problem can become especially acute when the perforated zone is long or there are a number of different perforated zones.
One method of attacking this flow imbalance problem involves the use of spherical ball sealers. These ball sealers have a diameter slightly larger than the average perforation size, and are pumped into the casing along with the treating fluid. The flow pattern of the fluid preferentially carries the ball sealers toward the casing perforations which have the highest flow rates of fluid passing into the surrounding formations. If a substantial number of the ball sealers seat against the high flow perforations, then fluid flow through those openings is blocked. The perforations which had relatively low flow rates before are now forced to receive the diverted flow. By thus redirecting at least some of the fluid toward the formations with the greatest resistance to flow, a more even flow distribution can be achieved. As a result, the increase in hydrocarbon recovery is larger than it would be if the flow imbalance was not corrected.
If a ball sealer has a greater specific gravity than the fluid injected, the force of gravity pulling down on the ball will be greater than the upward buoyant force. Therefore the ball will sink in a stagnant body of the fluid. When the additional downward drag force exerted on the ball by the downwardly flowing fluid is taken into account, the ball's downward velocity obviously becomes relatively high. This relatively high downward velocity can cause some of the balls to overshoot the perforated zone and sink to the bottom of the well. U.S. Pat. Nos. 4,102,401 and 4,244,425, both to Erbstoesser, teach the use of ball sealers which have a specific gravity less than that of the injected fluids. Balls with lower specific gravity will have a net velocity, considering the gravitational and buoyant forces only, that is upward, not downward like denser balls. Therefore, when the downward drag force exerted on the ball by the fluid is taken into account, the ball's downward velocity will be substantially less than if it had a higher specific gravity.
Reducing the ball's downward velocity reduces the chance that it will overshoot the perforated zone. Further, even if a ball does overshoot, the fluid beneath the perforated zone is stagnant so that ball experiences no downward drag force in that region. Thus, balls that do overshoot will rise back into the perforated zone. Because low specific gravity balls will not sink to the well bottom where they cannot help redistribute flow, they are usually more effective in combatting this problem than are denser balls.
Although ball sealers have proven useful for reducing flow imbalances, several problems remain in their use. First, the ball sealers must operate in an hostile environment. When seated against a perforation, a ball sealer usually experiences a large pressure differential between the fluid in the casing and the fluid in the surrounding formation. In addition, the temperature in the well during fluid injection operations is frequently high. Ball sealers tend to undergo heat distortion under these conditions. When the spherical shape of a ball sealer distorts, its strength is significantly reduced and failure is much more likely. If too many of the injected ball sealers fail, the desired flow correction cannot be achieved.
Further, some prior art ball sealers have presented manufacturing problems. Some balls made of "syntactic foam" (hollow spherical particles dispersed in some kind of binder) tend to crystallize when they are cured. The crystallization affects the overall specific gravity of the ball. Since this property is important to the ball's operation, crystallization causes an undesirably high percentage of rejects in the manufacture of syntactic foam balls.
In addition, there remains a need for ball sealers which can withstand even greater temperature and pressure than the balls currently in use.